Third Quarter 2020 Investor Presentation...1. Updated 2020 outlook provided May 6, 2020; Enable...
Transcript of Third Quarter 2020 Investor Presentation...1. Updated 2020 outlook provided May 6, 2020; Enable...
Enable Midstream Partners, LP
Third Quarter 2020 Investor Presentation
Forward-looking Statements
Some of the information in this presentation may contain forward-looking statements. Forward-looking statements give our current
expectations and contain projections of results of operations or of financial condition, or forecasts of future events. Words such as
“could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,”
“believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements.
Without limiting the generality of the foregoing, forward-looking statements contained in this presentation include our expectations of
plans, strategies, objectives, growth and anticipated financial and operational performance, including our 2020 outlook presented in
our first quarter 2020 financial results press release dated May 6, 2020, which is reaffirmed in this presentation. In particular, our
statements with respect to continuity plans and preparedness measures we have implemented in response to the novel coronavirus
(COVID-19) pandemic and its expected impact on our business, operations, earnings and results are forward-looking statements.
Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no
forward-looking statements can be guaranteed.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We
believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering
these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this presentation, our
Quarterly Report on Form 10-Q for the three months ended March 31, 2020 (March 31 Quarterly Report), and our Annual Report on
Form 10-K for the year ended Dec. 31, 2019 (Annual Report). Those risk factors and other factors noted throughout this
presentation and in our March 31 Quarterly Report and Annual Report could cause our actual results to differ materially from those
disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements.
Any forward-looking statements speak only as of the date on which such statement is made, and we undertake no obligation to
correct or update any forward-looking statement, whether as a result of new information or otherwise, except as required by
applicable law.
2
Non-GAAP Financial Measures
3
Gross margin, Adjusted EBITDA, Adjusted interest expense, Distributable cash flow (DCF) and Distribution coverage ratio are not
financial measures presented in accordance with GAAP. Enable has included these non-GAAP financial measures in this
presentation based on information in its consolidated financial statements.
Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio are supplemental financial
measures that management and external users of Enable’s financial statements, such as industry analysts, investors, lenders and
rating agencies may use, to assess:
• Enable’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry,
without regard to capital structure or historical cost basis;
• The ability of Enable’s assets to generate sufficient cash flow to make distributions to its partners;
• Enable’s ability to incur and service debt and fund capital expenditures; and
• The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment
opportunities.
This presentation includes a reconciliation of Gross margin to total revenues, Adjusted EBITDA and DCF to net income attributable
to limited partners, Adjusted EBITDA to net cash provided by operating activities and Adjusted interest expense to interest expense,
the most directly comparable GAAP financial measures, as applicable, for each of the periods indicated. Distribution coverage ratio
is a financial performance measure used by management to reflect the relationship between Enable's financial operating
performance and cash distributions. Enable believes that the presentation of Gross margin, Adjusted EBITDA, Adjusted interest
expense, DCF and Distribution coverage ratio provides information useful to investors in assessing its financial condition and
results of operations. Gross margin, Adjusted EBITDA, Adjusted interest expense, DCF and Distribution coverage ratio should not
be considered as alternatives to net income, operating income, revenue, cash flow from operating activities, interest expense or any
other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA, Adjusted
interest expense, DCF and Distribution coverage ratio have important limitations as analytical tools because they exclude some but
not all items that affect the most directly comparable GAAP measures. Additionally, because Gross margin, Adjusted EBITDA,
Adjusted interest expense, DCF and Distribution coverage ratio may be defined differently by other companies in Enable’s industry,
Enable’s definitions of these measures may not be comparable to similarly titled measures of other companies, thereby diminishing
their utility.
1. Enable Midstream Overview
1. Segment Overview
5. Appendix
4
Contents
AppendixEnable Midstream Overview
Enable Benefits from a Diversified Asset Portfolio
6
Note: Map as of Aug. 7, 2020
Fully integrated midstream platform serves
as a critical link between production and
downstream markets
Long-term relationships with large-cap
producers, LDCs and electric utilities, many of
whom are investment-grade
Transportation and storage segment is
anchored by firm contracts with high-quality
customers, providing stability during volatile
market environments
Over the long term, Enable is well-positioned
from both a producer operating cost and
wellhead pricing perspective, with Enable
providing unique markets for production and
many producers holding downstream capacity
commitments
Enable continues to work with both producers
and customers representing end markets to
facilitate competitive market solutions
Recent Business Highlights
7
COVID-19 safety protocols remain in place; continue to monitor local, state
and federal guidelines and recommendations from health organizations to
ensure the safety of employees, customers and communities
1. Updated 2020 outlook provided May 6, 2020; Enable reaffirmed this outlook Aug. 5, 2020
Reaffirmed 2020 outlook1 based on ongoing feedback from customers
on near-term plans
Achieved record natural gas gathered volumes in the Ark-La-Tex Basin for
second quarter 2020, while shut-in volumes were less than expected for
the quarter; certain Anadarko Basin lean gas wells are expected to remain
shut in through third quarter 2020 in anticipation of higher prices
On track to achieve previously announced capital and cost reductions
and remain committed to further action, as needed, based on market
conditions
Financial Highlights
8
• DCF exceeded declared distributions to common unitholders by $76 million for second quarter 2020 and
$218 million for the first half of 2020, fully funding expansion capital expenditures
• Substantial progress achieved on cost reduction initiatives with a focus on aligning Enable’s
organizational and cost structure for the current environment and providing for future flexibility
• Commercial dialogue continues for additional Gulf Run Pipeline project capacity commitments; financing
plans for the project to be finalized following final determination of pipeline scope
• Have experienced no meaningful credit losses to date
‒ Typically a net payor for natural gas processing producer customers
‒ Transportation and storage segment anchored by large, investment-grade utilities
• No remaining debt maturities in 2020 and 20211
• Repurchased approximately $22 million aggregate principal amount of senior notes in the open market
during second quarter 2020 for approximately $17 million plus accrued interest and will continue to
evaluate opportunistic note repurchases based on market conditions and available liquidity
1. Excluding Revolving Credit Facility and short-term Commercial Paper borrowings
Commercial Highlights
9
• Contracted or extended over 950,000 Dth/d of firm
transportation capacity during second quarter 2020,
including previously announced recontracted
capacity with EGT’s largest customer, CenterPoint
Energy Resources Corp (CERC)
• Received FERC approval of MRT’s rate case
settlements, resulting in a $17 million one-time 2020
revenue benefit from 2019 billings and an estimated
$7 million ongoing service revenue benefit1
• EGT’s MASS project is proceeding on schedule to
be placed into service in the second quarter of 2021
• Recently received a five-year commitment for
80,000 Dth/d of firm capacity for MRT’s Southbound
Expansion project with an anticipated fourth quarter
2020 in-service date
• Focused on recontracting upcoming expiring SESH
capacity
‒ SESH has seen a load factor of over 90% in
recent years and plays a key role in serving
utility markets in the Southeast
Gathering and Processing
100%
Fee-Based
Transportation and Storage
• Impacts from production shut-ins for second quarter
2020 were less than expected
‒ Shut-in wells in the SCOOP and STACK due to
lower crude prices are substantially back
online, but shut-ins have now shifted to leaner
wells in the STACK due to anticipated higher
natural gas prices2
‒ All but two Williston pads are now back online2
‒ With production that has come back online, no
degradation in well performance has been
experienced2
• Achieved record second quarter 2020 Ark-La-Tex
Basin natural gas gathered volumes3
‒ Haynesville Shale producers continue to invest
in the play, and the play’s long-term outlook
remains strong
• DUCs continue to build in the Anadarko and
Williston Basins
1. Compared to 2018, the last year unaffected by these rate cases and recent capacity turnback
2. As of August 5, 2020
3. Since the partnership’s inception
Built for the Long Term
10
Critical link between production and downstream markets
Diversified assets with proven value, scale and upside
Favorable contract structures with significant fee-based
and demand-fee margin
Continue to recontract transportation capacity on a long-
term basis and develop new, capital-efficient
transportation projects
Actions announced in Q2-20 fully fund the 2020 business
plan with internally generated cash flows and further
strengthen Enable’s balance sheet, financial flexibility and
liquidity
~97% Fee-Based or Hedged Margin2Key Enable Highlights
Large Scale, Fully-Integrated Midstream Platform1
10,000 Miles Interstate/Intrastate
Pipelines
2.6 Bcf/d Processing Capacity
14,000 Miles Gathering Pipelines
84.5 BcfNatural Gas
Storage Capacity
1. Pipeline miles are approximate and interstate/intrastate pipeline miles include ~7,800 miles of interstate pipeline (including SESH) and ~2,200 miles of
intrastate pipeline
2. Gross margin profile represents hedges as of July 10, 2020, and Enable’s latest internal 2020 forecast and price assumptions for the balance of the year
48%
44%
5%3%
Fee-Based Volume Dependent Fee-Based Demand
Commodity-Based Hedged Commodity-Based Unhedged
AppendixSegment Overview
Gathering and Processing Segment
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Note: Map as of Aug. 7, 2020 and SCOOP counties are designated as Caddo, Carter, Garvin, Grady, McClain and Stephens and STACK counties are designated
as Blaine, Canadian, Custer, Dewey, Kingfisher, Major and Woodward counties of Oklahoma
1. As of Dec. 31, 2019
Gathering and Processing Highlights Basin Highlights
Anadarko
Natural Gas
We have natural gas gathering and
processing operations in the SCOOP,
STACK, Granite Wash, Cleveland,
Marmaton, Tonkawa, Cana Woodford
and Mississippi Lime plays. Enable
serves over 200 producers1 in the
Anadarko Basin and has secured 5.0
million gross acres1 of dedication under
long-term, fee-based contracts.
Crude Oil and Condensate
Our operations in the Anadarko Basin
include gathering of crude oil and
condensate from producers in the
SCOOP, STACK and Merge plays.
Arkoma
Our operations primarily serve the
Woodford Shale play located in
Oklahoma and the Fayetteville Shale
play located in Arkansas. Our Arkoma
Basin gathering and processing
operations serve both rich and lean
gas production from approximately 80
producers1. Contracts are primarily
fee-based contracts with significant
support from MVCs, which have a
weighted average remaining term of
4.7 years1.
Williston
We have operations in the Bakken
Shale that are located in North Dakota.
The focus of our operations in the
Williston Basin is the gathering of
crude oil and produced water for XTO
Energy Inc., an affiliate of ExxonMobil
Corporation, with pipeline gathering
systems in Dunn, McKenzie, Williams
and Mountrail counties of North
Dakota.
Substantial size and scale in prominent basins
underpinned with favorable contract structuresArk-La-Tex
We have gathering and processing
operations in the Ark-La-Tex Basin
located in Arkansas, Louisiana and
Texas. Our Ark-La-Tex gathering and
processing operations primarily serve
the Haynesville, Cotton Valley and the
lower Bossier plays. We serve
approximately 90 producers1 in the
Ark-La-Tex Basin where our gathering
and processing operations provide
service for both rich and lean gas
production. The scale of Enable’s Ark-
La-Tex Basin assets allows us to be
well-positioned to supply demand
growth from LNG exports.
• 15 Processing Plants with ~2.6 Bcf/d of processing capacity1
• 8.2 million gross acres dedicated under gathering agreements with a
volume-weighted average remaining term of 4.3 years1 for natural gas
and 11.8 years1 for crude oil and condensate
• 2019 Gathering and Processing segment gross margin was 80% fee-
based1
13
Note: Map as of Aug. 7, 2020
1. As of Dec. 31, 2019; excludes SESH which is reported as an equity method investment
2. 50/50 joint venture with Enbridge Inc.
EGT (Enable Gas
Transmission, LLC)
MRT(Enable Mississippi
River Transmission,
LLC)
SESH(Southeast Supply
Header, LLC)
• Serves utilities, industrial end-users and producers, providing access to Mid-continent supply and other
Northeastern, Mid-continent and Gulf Coast markets through interconnects
• Serves utilities and industrial end-users, providing access to Mid-continent supply and Northeastern
supply through interconnects
• Primarily serves customers that generate electricity for the Florida power market and interconnects to
pipelines serving major Southeast and Northeast markets
• Serves utilities, industrial end-users and producers, including growing Anadarko Basin productionEOIT(Enable Oklahoma
Intrastate Transmission,
LLC)
2
100% Derived from
Fee-Based Contracts
93% Derived from
Firm Contracts
Transportation and Storage Segment
EOIT
EGT
100%
Fee-Based
System Map and Highlights Transportation and Storage Gross Margin1
EGT 59%
MRT 11%
EOIT 23%
Gulf Run Pipeline Project
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• The Gulf Run Pipeline project, backed by a 20-
year commitment with cornerstone shipper
Golden Pass LNG, will provide access to
some of the most prolific natural gas
producing regions in the U.S.
• FERC’s current schedule anticipates an
environmental assessment will be issued by
Oct. 29, 2020
• Project will be appropriately sized to meet
contracted customer capacity commitments,
and the capital cost estimate to meet Golden
Pass’s current 1.1 Bcf/d commitment capital is
approximately $500 million1
• Expected to be placed into service in late
2022, subject to FERC approval
Project
AnnouncementOpen Season Survey Work FERC Pre-
Filing
Public Open
HousesFERC Scoping
MeetingsFERC 7(c)
Filing
FERC
ApprovalBegin
Construction
Project
Completed
2018 20222019 2021
Gulf Run Pipeline Project
Golden Pass
FID
Note: Map as of Aug 7, 2020
1. Excludes the estimated allowance for funds used during construction, which represents the approximate net composite interest cost of borrowed funds and a
reasonable return on the equity funds used for construction
2020
AppendixAppendix
2020 Outlook
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2020 Financial Outlook1
$ in millions
Net Income Attributable to Common Units1 $195 – $235
Adjusted EBITDA2 $900 – $960
Distributable Cash Flow2 $585 – $645
2020 Capital Outlook
$ in millions
Maintenance Capital $95 – $105
Gathering and Processing Segment $45 – $75
Transportation and Storage Segment $60 – $70
Total Expansion Capital $105 – $145
1. Our 2020 outlook was provided on May 6, 2020, and delivery of this presentation should not be viewed as a reaffirmation of such guidance
2. Net Income Attributable to Common Units includes a $20 million non-cash loss on retirement of a small natural gas gathering system in the Ark-La-Tex
that was recognized in Q2-20
2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
2020 outlook provided May 6, 2020, reaffirmed Aug. 5, 2020
Enable Ownership Structure
17Note: Structure as of June 30, 2020
Large, Diverse and High-Quality Customer Base
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Top Customers1
Enable’s revenues are strengthened by a diverse, high-quality customer base,
including many investment-grade or affiliates of investment-grade companies
(Investment Grade)
(Investment Grade) (Investment Grade)(Investment Grade)
• Many of our customers rely on us for multiple midstream services across both G&P and T&S
• Loyal customer base through exemplary customer service and reliable project execution
(Investment Grade)
(Investment Grade)
(Investment Grade)
(Investment Grade)
Note: Standard and Poor’s, Moody’s and Fitch credit ratings from Bloomberg as of Aug. 6, 2020
Investment grade rated indicates that the company has an investment-grade rating from Standard and Poor’s, Moody’s or Fitch
1. As of Dec.31, 2019
(Investment Grade)
(Investment Grade) (Investment Grade)
Three Months Ended June 30 Six Month Ended June 30
$ in millions, except per-unit and ratio data2020 2019 Change 2020 2019 Change
Total Revenues $515 $735 ($220) $1,163 $1,530 ($367)
Gross Margin1 $338 $418 ($80) $760 $835 ($75)
Net Income Attributable to Limited Partners $44 $124 ($80) $156 $246 ($90)
Net income Attributable to Common Units $35 $115 ($80) $138 $228 ($90)
Net Cash provided by Operating Activities $111 $212 ($101) $311 $427 ($116)
Adjusted EBITDA1
$224 $281 ($57) $510 $578 ($68)
Distributable Cash Flow1
$148 $197 ($49) $362 $405 ($43)
Distribution Coverage Ratio2
2.06x 1.37x 0.69x 2.51x 1.44x 1.07x
Cash Distribution per Common Unit $0.16525 $0.3305 ($0.16525)
Cash Distribution per Series A Preferred Unit $0.625 $0.625 $0
Financial Results
19
1. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
2. Non-GAAP measure calculated as distributable cash flow divided by distributions related to common units
Operational Performance Overview
20
Transported Volumes
Natural Gas Gathered Volumes Natural Gas Processed Volumes
TBtu/d
TBtu/d TBtu/d
• Natural gas gathered volumes decreased for second quarter 2020 compared to second quarter 2019 primarily as a result of shut-in
production in the Anadarko Basin, partially offset by higher gathered volumes in the Ark-La-Tex Basin
• Natural gas processed volumes decreased for second quarter 2020 compared to second quarter 2019 as a result of lower
processed volumes across all basins
• Crude oil and condensate gathered volumes decreased for second quarter 2020 compared to second quarter 2019 primarily as a
result of shut-in production in the Anadarko and Williston Basins
• Transported volumes decreased for second quarter 2020 compared to second quarter 2019 primarily as a result of decreased
production in the Anadarko Basin
Crude Oil and Condensate Gathered VolumesMBbl/d
10.4% Decrease
4.62 4.14
Q2 2019 Q2 2020
19.7% Decrease
2.54
2.04
Q2 2019 Q2 2020
29.0% Decrease
119.34
84.68
Q2 2019 Q2 2020
10.6% Decrease
6.04 5.40
Q2 2019 Q2 2020
Gathering and Processing Operational Results
21
1. Includes volumes under third-party processing arrangements
2. Excludes condensate
3. Before eliminations upon consolidation
4. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
Three Months Ended June 30 Six Months Ended June 30
2020 2019 Change 2020 2019 Change
An
ad
ark
o
Basin
Gathered Volumes (TBtu/d) 1.89 2.33 (0.44) 2.09 2.34 (0.25)
Processed Volumes (TBtu/d)1 1.73 2.08 (0.35) 1.90 2.10 (0.20)
NGLs Produced (MBbl/d)1,2 100.34 112.19 (11.85) 103.46 116.3 (12.84)
Crude Oil and Condensate Gathered Volumes (MBbl/d) 61.40 79.96 (18.56) 87.94 78.26 (9.68)
Ark
om
a
Basin
Gathered Volumes (TBtu/d) 0.39 0.49 (0.10) 0.41 0.49 (0.08)
Processed Volumes (TBtu/d) 1 0.08 0.10 (0.02) 0.08 0.10 (0.02)
NGLs Produced (MBbl/d) 1,2 4.05 7.02 (2.97) 3.97 6.63 (2.66)
Ark
-La
-Te
x
Basin
Gathered Volumes (TBtu/d) 1.86 1.80 0.06 1.83 1.75 (0.08)
Processed Volumes (TBtu/d) 0.23 0.36 (0.13) 0.26 0.34 (0.08)
NGLs Produced (MBbl/d) 2 8.39 10.89 (2.50) 9.39 11.20 (1.81)
Williston Basin Crude Oil Gathered Volumes (MBbl/d) 23.28 39.38 (16.10) 25.03 35.39 (10.36)
Financial Results ($ in millions)
To
tal
G&
P
Total Revenues3 $391 $587 ($196) $868 $1,217 ($349)
Gross Margin3,4 $215 $290 ($75) $481 $560 ($79)
Operation & Maintenance and G&A Expenses3 $92 $75 ($17) $173 $159 ($14)
Depreciation and Amortization $74 $78 $4 $148 $152 $4
Impairment - - - $28 - ($28)
Taxes other than Income Tax $11 $10 ($1) $22 $21 ($1)
Operating Income $38 $127 ($89) $110 $228 ($118)
Transportation and Storage Segment Results
22
1. Before eliminations upon consolidation
2. Non-GAAP financial measures are reconciled to the nearest GAAP financial measures in the Appendix
Operational Results
Three Months Ended June 30 Six Months Ended June 30
2020 2019 Change 2020 2019 Change
Transported Volumes (Tbtu/d) 5.40 6.04 (0.64) 5.98 6.36 (0.38)
Interstate Firm Contracted Capacity (Bcf/d) 5.78 6.38 (0.60) 6.13 6.45 (0.32)
Intrastate Average Deliveries (TBtu/d) 1.67 2.06 (0.39) 1.87 2.19 (0.32)
Financial Results ($ in millions)
Total Revenues1 $183 $252 ($69) $417 $568 ($151)
Gross Margin1,2 $124 $129 ($5) $280 $276 $4
Operation & Maintenance and G&A Expenses1 $45 $50 $5 $90 $95 $5
Depreciation and Amortization $31 $32 $1 $61 $63 $2
Taxes other than Income Tax $6 $7 $1 $13 $14 $1
Operating Income $42 $40 $2 $116 $104 $12
Consolidated Statements of Income
23
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
(In millions, except per unit data)
Revenues (including revenues from affiliates):
Product sales $ 196 $ 393 $ 484 $ 836 Service revenue 319 342 679 694
Total Revenues 515 735 1,163 1,530
Cost and Expenses (including expenses from affiliates): Cost of natural gas and natural gas liquids (excluding
depreciation and amortization shown separately) 177 317 403 695
Operation and maintenance 115 99 217 202 General and administrative 21 25 45 51 Depreciation and amortization 105 110 209 215 Impairments — — 28 — Taxes other than income tax 17 17 35 35
Total Cost and Expenses 435 568 937 1,198
Operating Income 80 167 226 332
Other Income (Expense):
Interest expense (46) (48) (93) (94) Equity in earnings of equity method affiliate 5 4 11 7 Other, net 5 1 5 1
Total Other Expense (36) (43) (77) (86)
Income Before Income Tax 44 124 149 246 Income tax benefit — — — (1)
Net Income $ 44 $ 124 $ 149 $ 247 Less: Net (loss) income attributable to noncontrolling interest — — (7) 1
Net Income Attributable to Limited Partners $ 44 $ 124 $ 156 $ 246 Less: Series A Preferred Unit distributions 9 9 18 18
Net Income Attributable to Common Units $ 35 $ 115 $ 138 $ 228
Basic earnings per unit
Common units $ 0.08 $ 0.26 $ 0.32 $ 0.52
Diluted earnings per unit
Common units $ 0.08 $ 0.26 $ 0.30 $ 0.52
Non-GAAP Reconciliations
24
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Gross margin to Total Revenues:
Consolidated
Product sales $ 196 $ 393 $ 484 $ 836 Service revenue 319 342 679 694
Total Revenues 515 735 1,163 1,530
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 177 317 403 695
Gross margin $ 338 $ 418 $ 760 $ 835
Reportable Segments
Gathering and Processing
Product sales $ 193 $ 379 $ 468 $ 802 Service revenue 198 208 400 415
Total Revenues 391 587 868 1,217
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 176 297 387 657
Gross margin $ 215 $ 290 $ 481 $ 560
Transportation and Storage
Product sales $ 59 $ 114 $ 134 $ 281 Service revenue 124 138 283 287
Total Revenues 183 252 417 568
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) 59 123 137 292
Gross margin $ 124 $ 129 $ 280 $ 276
Non-GAAP Reconciliations Continued
25
1. Change in fair value of derivatives includes
changes in the fair value of derivatives that
are not designated as hedging instruments
2. Other non-cash losses includes write-
downs and net loss on sale and retirement
of assets
3. This amount represents the quarterly cash
distributions on the Series A Preferred
Units declared for the three and six months
ended June 30, 2020 and 2019. In
accordance with the Partnership
Agreement, the Series A Preferred Unit
distributions are deemed to have been paid
out of available cash with respect to the
quarter immediately preceding the quarter
in which the distribution is made
4. Distributions for phantom and performance
units represent distribution equivalent
rights paid in cash. Phantom unit
distribution equivalent rights are paid
during the vesting period and performance
unit distribution equivalent rights are paid
at vesting
5. See the next slide for a reconciliation of
Adjusted interest expense to Interest
expense
6. Represents cash distributions declared for
common units outstanding as of each
respective period. Amounts for 2020 reflect
estimated cash distributions for common
units outstanding for the quarter ended
June 30, 2020
7. Distribution coverage ratio is computed by
dividing DCF by Distributions related to
common unitholders
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
(In millions, except Distribution coverage ratio)
Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners $ 44 $ 124 $ 156 $ 246 Depreciation and amortization expense 105 110 209 215 Interest expense, net of interest income 45 47 92 93 Income tax benefit — — — (1)
Distributions received from equity method affiliate in excess of equity earnings 4 — 8 9
Non-cash equity-based compensation 3 5 7 9
Change in fair value of derivatives (1) 12 (11) 2 1
Other non-cash losses (2) 7 6 12 7 Impairments — — 28 — Gain on extinguishment of debt 5 — 5 — Noncontrolling Interest Share of Adjusted EBITDA (1) — (9) (1)
Adjusted EBITDA $ 224 $ 281 $ 510 $ 578
Series A Preferred Unit distributions (3) (9) (9) (18) (18)
Distributions for phantom and performance units (4) (1) — (1) (9)
Adjusted interest expense (5) (45) (49) (92) (96) Maintenance capital expenditures (22) (26) (38) (50) Current income taxes 1 — 1 —
DCF $ 148 $ 197 $ 362 $ 405
Distributions related to common unitholders (6) $ 72 $ 144 $ 144 $ 282
Distribution coverage ratio (7) 2.06 1.37 2.51 1.44
Non-GAAP Reconciliations Continued
26
1. Other non-cash items includes write-downs and net loss on sale and retirement of assets
2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities $ 111 $ 212 $ 311 $ 427 Interest expense, net of interest income 45 47 92 93
Noncontrolling interest share of cash provided by operating activities (1) — (2) (1)
Current income taxes 1 1 1 —
Other non-cash items (1) (2) 4 2 4
Changes in operating working capital which (provided) used cash:
Accounts receivable 30 (28) (30) (57) Accounts payable 12 57 70 112
Other, including changes in noncurrent assets and liabilities 12 (1) 56 (10)
Return of investment in equity method affiliate 4 — 8 9
Change in fair value of derivatives (2) 12 (11) 2 1
Adjusted EBITDA $ 224 $ 281 $ 510 $ 578
Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense $ 46 $ 48 $ 93 $ 94 Interest income (1) (1) (1) (1) Amortization of premium on long-term debt — 2 1 3 Capitalized interest on expansion capital 1 — 1 1 Amortization of debt expense and discount (1) — (2) (1)
Adjusted interest expense $ 45 $ 49 $ 92 $ 96
2020 Forward-Looking Non-GAAP Reconciliations
27
1. Net income attributable to limited partners range based on adding Series A Preferred Unit distributions to the net income attributable to common units
outlook
2. Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments
3. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to
the quarter immediately preceding the quarter in which the distribution is made
2020 Outlook
(In millions)
Reconciliation of Adjusted EBITDA and distributable cash flow to net income
attributable to limited partners and calculation of Distribution coverage ratio:
Net income attributable to limited partners (1)$231 – $271
Depreciation and amortization expense $415 – $425
Interest expense, net of interest income $174 – $184
Income tax (benefit) expense $0
Distributions received from equity method affiliate in excess of equity
earnings$5 – $11
Non-cash equity based compensation $19
Change in fair value of derivatives (2)$10
Other non-cash losses $23
Impairments $28
Noncontrolling Interest Share of Adjusted EBITDA ($8)
Adjusted EBITDA $900 – $960
Series A Preferred Unit distributions (3)($36)
Adjusted interest expense ($170) – ($180)
Maintenance capital expenditures ($95) – ($105)
Other ($4)
DCF $585 – $645
2020 Forward-Looking Non-GAAP Reconciliations Continued
28
*Enable is unable to present a quantitative reconciliation of forward-looking Adjusted EBITDA to net cash provided by operating
activities because certain information needed to make a reasonable forward-looking estimate of changes in working capital which
may (provide) use cash during the calendar year 2020 cannot be reliably predicted and the estimate is often dependent on future
events which may be uncertain or outside of Enable's control. This includes changes to accounts receivable, accounts payable and
other changes in non-current assets and liabilities.
2020 Outlook
(In millions)
Reconciliation of Adjusted interest expense to Interest expense:
Interest expense, net of interest income $176 – $186
Interest income ($2)
Amortization of premium on long-term debt $1
Capitalized interest on expansion capital $0
Amortization of debt expense and discount ($5)
Adjusted interest expense $170 – $180